29031LNG shipowners seek profit in niches9/13/2019 9:37:46 AMhttps://www.petroleum-economist.com/articles/midstream-downstream/lng/2019/lng-shipowners-seek-profit-in-nichesBeatrice Bedeschihttps://www.petroleum-economist.com/media/6882/lng-taitar-2-1.jpgBulk LNG shipping would appear to be in a rosy position—global trade volumes have never been higher. Yet shippers are relatively glum about the short-term prospects for large-scale LNG transport, and much more enthused about the prospect of LNG bunkering and floating storage and/or regasification units (FSRUs/FSUs/FRUs). Why?

Admittedly, longer-term, shippers are more positive. Future mega-projects are being approved almost on a monthly basis, on the back of bullish forecasts of gas as, at the very least, a bridge fuel in the energy transition. As a result, the order book for new ships to serve this projected volume growth is bulging.

But the current low LNG price environment is a major issue, Mike Rowley, senior advisor, LNG and offshore at ship operator Mitsui OSK Lines (MOL), told the London LNG Shipping conference. It has meant increased competition between players and shorter contract terms—leading to larger LNG projects becoming "more complex and capital intensive" and to "difficult commercial terms for shipowners", says Rowley

"Global downside and economic uncertainty will continue to overshadow growth in the LNG business sector for the foreseeable future," he says, citing issues such as the US-China tariff dispute, as well as Brexit, which "might have some impact".

As a result, "small-scale bunker vessels are the new direction in which we are heading," says Rowley. MOL currently has two bunker vessels under order, one contracted with Total with a capacity of 18,600m³, due to be delivered in Q1 2020, and one of 12,000m³ capacity due to be delivered in Q1 2021.

In addition, MOL is "well into the space" for FRSUs and FSUs, with the conversion of older LNG tankers into floating units.

"Global downside and economic uncertainty will continue to overshadow growth in the LNG business sector for the foreseeable future" — Mitsui OSK Lines

Even floating units, with their potential to swiftly bring gas to new regions, particularly to "emerging and frontier markets" in the developing world, face challenges, warns Suryan Wirya Simunovic, executive vice president at Golar Management, the ship management arm of Norway's Golar.

"What we are seeing increasingly is the huge challenge in developing import solutions," he says. "Technically there are many solutions but getting these projects over the line is the hurdle.

"The immense frustration I face is that you take these projects almost down to the finish line, and then it does not happen for whatever reason—whether it is this minister or that CEO… And that is the challenge."

Golar's fleet includes eight FSRUs, of which four are converted LNG vessels, and three floating liquefaction vessels (FLNGVs), as well as 16 conventional LNG tankers.

"We are focusing on medium scale and on developing floating regas solutions," says Jostein Ueland, co-founder of Oslo-based start-up Dreifa Energy. The firm aims to provide FSU and FRU solutions on short contract durations to meet immediate demand but with optionality for future requirements, helping to "develop new markets and build new demand" for LNG.

"This is where the shipping market is going" says Ueland, adding that there is a "significant number of vessels that are 20-30-40 years old, that are not good for transportation but are fantastic storage vessels, low cost and can be brought in for a gas plant or industrial users around the world".

]]>29030Turkey tucks into bargain US LNG9/13/2019 7:21:49 AMhttps://www.petroleum-economist.com/articles/midstream-downstream/lng/2019/turkey-tucks-into-bargain-us-lngGerald Butthttps://www.petroleum-economist.com/media/6880/lng-small.jpgTurkey cut its total pipeline imports by 3.55bn m³, or 18pc, to 16.15bn m³ in the first half of 2019, ramping up instead LNG deliveries as the Atlantic Basin bathed in a sea of plentiful supply and low prices.

Russian pipeline imports—it also receives cross-border flows from Iran and Azerbaijan—took the most significant hit. Delivered volumes in the first half of the year were down by 4.5bn m³, or 36pc, to 8bn m³, leaving Russia supplying just 34pc of Turkey’s import requirements. In contrast, Russia took a 47pc slice of Turkey’s 50.35bn m³ 2018 import pie.

Pipeline imports have lost out to LNG, with ship-borne volumes totalling almost 7.15bn m³ in the first half of 2019, up by 0.9bn m³ from just under 6.25bn m³ in the same period last year. In particular, there has been a significant increase in LNG imports from the US. In January-to-June this year, Turkey imported 884mn m³ via five cargoes of LNG from the US, compared to six cargoes for the whole of 2018.

The key reason is low prices and Gazprom’s refusal to reduce its price, says Ellinas

And Turkey is not alone in finding LNG from the US to its liking. In the whole Mena region, a total of 18 cargoes were delivered in 2018, while up to June this year the tally of arrivals had already reached 15. Jordan leads the way with six cargoes in the first half of 2019, again closing in on its total for the whole of 2018. The United Arab Emirates, which both imports and exports LNG, took three cargoes in January-June, compared to just once across 2018.

Over the period from February 2016, when US exports began, until mid-2019, Mena countries have been destinations for 10pc of American LNG. Kuwait, Israel and Egypt (which is no longer an importer) also received US LNG across this period, but only Kuwait took a 2019 cargo up to June.

Attractive price

US Department of Energy figures show that in June this year the average price of US LNG was $4.39/mnBtu, down from $5.66/mnBtu at the start of the year.

Appetite for LNG from the US “is driven by a number of factors”, says East Med gas analyst Charles Ellinas. “But the key reason is low prices and [for Turkey] Gazprom’s refusal to reduce its price. As a result of lower demand in Asia, US LNG is being diverted to Europe, Turkey and the Mena region at very low prices, at uneconomic netbacks.”

The desire of both Turkey and Jordan to diversify sources of supply is another factor, as is the flexibility of spot LNG as the countries seek back-up for increased variable renewable power generation.

Source: US Department of Energy

But while the current prices make US LNG attractive, Ellinas cautions that its allure may not last. With the 31.5bn m³/yr Turkstream pipeline under the Black Sea from Russia to Turkey coming online and “LNG prices edging upwards next year, the situation may change”. “The appetite for US gas will remain only as long as the price remains low,” says Ellinas. “It is unsustainable in the longer term.”

There is also a limit to how much Turkey, and indeed other Mena countries with pipeline imports, can simply turn down these volumes to replace them with cheap spot LNG. Long-term contracts underpin the vast majority of these deliveries—while buyers have been renegotiating deals to try to increase both price and volume flexibility in recent years, often they have prioritised the former, sometimes even to the detriment of existing terms for the latter.

Source: US Department of Energy

At some point, Turkey’s ability to turn down and postpone its contracted Russian gas deliveries will rub up against the barriers of its take-or-pay obligations.

Turkey also significantly boosted its Algerian LNG imports in the first half of the year—up by almost 0.8bn m³, or 37pc, to just shy of 2.95bn m³ while reducing its Qatari take—down by more than 0.65bn m³ to under 1.3bn m³. Reducing the latter, given it is most likely oil-linked contract supply, looks like a logical move, while the increase in the former could suggest some deliveries via contract, but topped up by active spot buying from a very proximate buyer who may have been offering competitive pricing.

The country also imported smaller volumes of LNG from Nigeria, Norway and Trinidad, again most likely on a spot and keenly priced basis. Turkey gas has two onshore LNG regasification units (one at Marmara Ereglisi on the Marmara coast, the other at Aliaga on the Aegean) and two offshore units (at Aliaga and at Dortyol on the Mediterranean). Their combined receiving capacity is more than 20bn m³/yr.

]]>29025Argentinian crisis puts shale in limbo9/12/2019 6:06:33 PMhttps://www.petroleum-economist.com/articles/politics-economics/south-central-america/2019/argentinian-crisis-puts-shale-in-limboCharles Wainehttps://www.petroleum-economist.com/media/6877/fernandez_argentina-1.jpgArgentina is heading towards a general election on 27 October with near certainty that the reins of power will return to a Peronist government—headed by a partnership between presidential frontrunner Alberto Fernandez and former president Cristina Kirchner.

Sitting president Mauricio Macri's hopes of extending his tenure for another four years were dealt a severe blow by the national primary, which qualifies candidates for the October poll. A lack of confidence in the government's ability to restore economic stability saw Macri record just 32.1pc of the vote compared with 47.7pc for Fernandez, which would almost certainly be enough to win the election outright.

Investors are concerned that Fernandez would return the country to the market-unfriendly policies of the previous Kirchner government. The result of the primary triggered a loss of more than 25pc to the value of the peso. The government was quickly forced to appeal to the IMF for permission to delay its repayments of its record $101bn loan and to restrict purchases of dollars.

Conflicting statements from Fernandez' Judicialist Party about the future of Vaca Muerta shale has similarly rattled investors' nerves. First, there was a reassuring message. "One of [Fernandez'] advisors, Guillermo Nielsen, said that they aim to stimulate Vaca Muerta shale production by providing a legal framework that puts the area in an equal standing to unconventional resource areas in the US," says Ignacio Labaqui, senior analyst at macroeconomic research analyst Medley Global Advisors.

But, in a speech to the Spanish parliament in Madrid, Fernandez struck a different tone. "There is no point in having oil if, in order to extract it, you have to let multinationals come and take it away," he said.

Former minister of energy Juan Jose Aranguren, a political opponent, called a Buenos Aires radio station to say the statement was reminiscent of Venezuela, which once produced nearly 3.5mn bl/d of oil but now produces less than 1mn bl/d.

Setting sights

Argentina has only recently committed itself to an ambitious raft of upstream targets. Last year, the country released an Energy Plan, aimed at doubling both crude and natural gas output by 2023—a target of 1mn bl/d and 8.4bn ft³/d respectively. Argentina aspires to further boost this to 1.5mn bl/d and 14.1bn ft³/d by 2030.

The bulk of this growth was expected to come from the unconventional Vaca Muerta resources. YPF, the state-controlled energy company, holds 40pc of total acreage and has shouldered most of the development work to date—the company is the largest shale producer, responsible for 75pc of total output.

"Argentina will remain a country on the edge of default, with suspicion among many energy companies that, at the first hint of revenue or economic crisis, the Fernandez government will not hesitate to break contracts" Jones, Baker Institute

YPF plans to boost production by 5-7pc annually. The firm aims to ramp up output from its three main projects before the end of the year: Loma Campana (a joint venture with Chevron), La Amarga Chica (with Malaysia's Petronas) and Bandurria Sur (with US services firm Schlumberger). Loma Campana is expected to increase production from 40,000bl/d to over 50,000bl/d, La Amarga Chica from 10,000bl/d to 20,000bl/d and Bandurria Sur from 5,000bl/d to over 10,000bl/d. Combined, total investment stands at over $1.5bn and there are plans for 780 wells across the three projects by 2023.

The firm has significantly reduced costs in the shale play. Loma Campana, the first commercial project in the region, has cut development costs by 50pc since 2014, to $9/bl oe, while opex has similarly fallen 54pc over the same period to $5.50/bl oe. The ambition is to reduce this even further to $8/bl oe and $6/bl oe in opex by 2023.

Improvements in technology have also increased efficiency. Horizontal drilling at Loma Campana has boosted estimated ultimate recovery from 300,000bl per well to 1mn bl per well. Estimates of ultimate recovery have increased by 35pc over the period 2016-18, and drilling time for a 2,250m lateral well cut to just 29 days—from a previous spell of 53 days for a horizontal well of 1,000m. Argentinian financial consultant TPCG says YPF is now targeting 23 days by 2020.

The question is whether YPF can replicate the successes of Loma Campana across its other projects and compete economically with international shale. The development cost of horizontal drilling in La Amarga Chica still stands at $12/bl oe, while logistical costs for frack sand across the Vaca Muerta remains at $180-200/t, compared with $35-40/t in the Eagle Ford shale play.

Troubles ahead

The unfolding economic crisis will likely dampen Argentina's hopes of fulfilling its upstream targets in the near-term, particularly for natural gas. "For at least the next year or two, Argentina will be facing an economic crisis," says Mark P. Jones, a fellow in political science at Rice University's Baker Institute thinktank.

"This combination will give pause to large-scale investments with a medium to long-term time horizon that are necessary to deepen natural gas development in Argentina, such as LNG facilities to export natural gas to global markets, petrochemical plants to take advantage of the country's vast natural gas supply, and railways, roads and pipelines that are needed to drill and to ship natural gas to market."

The expansion of the Vaca Muerta is chiefly hamstrung by a lack of pipeline infrastructure. As of 2018, crude evacuation capacity stood at just 650,000bl/d and gas capacity at 5.8bn ft3/d. The government plans to rectify this situation and, in July, issued a tender for a $2bn gas pipeline linking Vaca Muerta to the town of Salliquelo, outside Buenos Aires, aimed for completion in 2021.

YPF also says it will push ahead with plans to develop a $5bn LNG plant to boost export capacity beyond the Tango floating LNG facility in Bahia Blanca. "In all likelihood, this project will move forward, but it may get delayed," says Pavel Molchanov, senior vice president and equity research analyst at US bank Raymond James.

Interest from international companies may be similarly affected by the current economic turmoil. This year, ExxonMobil announced it was targeting 55,000bl/d from phase one of its development in the Bajo del Choique-La Inverno block. US independent ConocoPhillips also stated it was partnering with Germany's Wintershall Dea in the Aguada Federal and Bandurria Norte blocks.

$9/bl oe — Loma Campana development cost

But moving projects from the pilot stage into development has been slow. Of 34 concessions granted, only five have reached full development and 13 concessions are due to expire between 2019-21.

Of the 13, according to a report from US thinktank the Institute for Energy Economics and Financial Analysis (IEEFA), only five have so far delineated investment plans: La Amarga Chica, Bandurria Sur, and Shell's Sierras Blancas, Cruz de Lorena and Coirón Amarga Sur Oeste projects.

Following the 11 August primary, the government also decided to freeze crude and fuel prices for three months. Initially, the currency exchange rate for crude transactions was capped at ARS45.19/$ but was later increased to ARS46.69/$. The government also issued a subsidy for producers that bolstered the exchange rate to ARS49.50/$.

The province of Neuquen threatened to challenge the decision in federal court, claiming a loss of royalties, although it has since withdrawn its action.

YPF said in an investor call it would reduce capex by $100-120mn/month while the freeze remains in place. The move will cost oil companies "$120mn less Ebitda per month, or 3pc less Ebitda per month", says Guido Bizzozero, senior analyst at Argentinian financial firm Allaria Ledesma & Cia.

"For the time being, Argentina will remain a country on the edge of default, with a high country risk rating. There is suspicion among many energy companies that, at the first hint of revenue or economic crisis, the Fernandez government will not hesitate to break contracts and/or intervene directly in the energy market to these companies' detriment," says Jones.

]]>29022West of Shetland MandA proves positive9/12/2019 5:45:09 PMhttps://www.petroleum-economist.com/articles/upstream/exploration-production/2019/west-of-shetland-ma-proves-positiveCraig Guthriehttps://www.petroleum-economist.com/media/6876/west-of-shetland-1.jpgSiccar Point Energy remains bullish on its core West of Shetland (WoS) region on the UK continental shelf (UKCS), based on its excellent exploration and production potential. And it is unfazed at recent M&A activity that has seen some US majors make or plan exits from the province.

The firm, founded in 2014 with backing from private equity (PE) heavyweights Blue Water Energy and Blackstone Energy, operates WoS assets including the Cambo field, with estimated reserves of 900mn/boe of oil-in-place. Its CEO Jonathan Roger told Petroleum Economist on the sidelines of Aberdeen's Offshore Europe conference that Cambo could be sanctioned as soon as early next year.

The WoS story has been generally positive, but there have been a few bumps in the road of late. Is that simply to be expected in a relatively frontier area? Do you retain your WoS enthusiasm?

Roger: Siccar Point sees the WoS as the most exciting growth area in the UK. The statistics make the potential there clear. [Consultancy] Wood Mackenzie estimates that 50pc of UK production will come from the area in the next decade, and around 50pc of the UK's exploration potential is also sitting in the region.

The WoS is absolutely a core part of our business and we are very positive on its future. It is a little more challenging than other parts of the UK, but not dramatically so. Compared to the northern North Sea, for example, the environmental conditions are not significantly different.

"The right people and resources are in place to develop the West of Shetland's potential" —Roger, Siccar Point

Are you slightly surprised that some larger global players are still selling down and out of WoS? Or is that just an opportunity for existing and new actors to expand their positions and for overall ownerships structures to become even more strategically aligned?

Roger: There is a need to explore who the sellers and buyers really are in that area. Yes, we have seen a retreat by US-headquartered majors, but also a positive consolidation where the likes of BP, Shell and Equinor are concerned. These firms all see the WoS as core parts of their portfolio.

This is not a 'majors exodus' story, it is necessary to look at all the different levels of activity there and understanding what is driving it. This is all positive for us as the right people and resources are in place to develop the region's potential.

There are obviously UKCS assets out there for sale. Given that Siccar Point has kept its powder relatively dry since its late 2016 OMV deal, might we expect any activity if assets that align with your core areas become available?

Roger: We are sitting on one of the largest discovered resource bases on the UKCS-well over half-a-billion bl of discovered resources. Look at our portfolio-long-life, low-cost assets with no decommissioning issues and production planned out to the 2050s. On the other hand, look at some of the other businesses, they do not necessarily fit from a quality standpoint.

So, our focus is very much on organic growth. Mariner has recently come on stream, there are the Cambo and Rosebank developments, so the plan is to take this business to 80,000bl/d by the mid-2020s.

I am sure that we have got the firepower to do other deals if we see the right one. But it needs to fit with us in terms of quality-that is the lens we put on it.

If we look ahead to PE investors' exit from the North Sea, and should your story lead to an IPO, what is the differentiation that Siccar Point will bring to market to attract equity investors that may not be particularly excited about oil and gas?

Roger: Our business is highly differentiated. Building this business, we have focused on creating something that is unique in terms of its quality and growth potential. That stands us in very good stead whatever form that exit ultimately involves. Our combination of long-life assets and low operating costs, along with discipline and innovation, really makes us a unique business on the UKCS. In addition, we are focused on WoS, the UK's last big growth area.

The UKCS often gets bucketed altogether. But you have really got to look at the different regions of the UK and the different maturity levels.

]]>29019Technology key to meeting Paris Agreement9/12/2019 1:47:49 PMhttps://www.petroleum-economist.com/articles/low-carbon-energy/renewables/2019/technology-key-to-meeting-paris-agreementAlastair O’Dellhttps://www.petroleum-economist.com/media/6873/paris-agreement-tech-1.jpgExisting technology would be enough to contain global warming to the COP21 pledge of 1.5°C but only if the energy transition is backed by strong enforcement of policies set out in the Paris Agreement, according to standards agency DNV GL at its annual Energy Transition Outlook event. Crucially, it also predicts that the transition would be affordable.

DNV GL predicts that energy use will peak by 2030, when efficiency improvements start to outpace economic growth. However, although it foresees a rapid energy transition—with a doubling of electricity in the demand mix by 2050 and a steep decline in oil from 2030—it does not expect emissions to fall fast enough to limit warming to 2°C. The forecast predicts 2.5°C, which "should set alarm bells ringing", says Remi Eriksen, the firm's CEO.

"We forecast a very rapid transition unfolding, within the timespan of one generation. Existing technology can deliver on the Paris Agreement, but only with broad and strong policy backing," he says.

The cost of the transition will be eased by another of its predictions—that the cost of energy will consume a lower share of global GDP. "The technology that can deliver a rapid transition already exists," says Eriksen, referring to solar panels, battery storage, carbon capture and storage, hydrogen and renewables.

"Our forecast does not reach for a magical solution or a revolution. Rather, it is the reducing costs of existing technologies which make a big difference," he continues, noting that each time the capacity of an energy source doubles its cost decreases—depending on its maturity—by a double-digit percentage.

The world relies on fossil fuels for 80pc of its energy needs and the report predicts this will reduce to 56pc in 2050. It also forecasts that energy consumption growth will rapidly decouple from GDP and population growth, to which it has historically been correlated. "In the next three decades we expect the global economy to grow by as much as 130pc," says Erikson. "But, at the same time as we grow more prosperous, that growth will use less energy and make less CO2."

DNV GL expects aggregate energy demand to peak in 2030 due to a combination of factors including efficiency gains from electrification, in residential and industrial uses, through technologies such as heat pumps. Further efficiency savings will come from 'smarter' buildings.

“At the same time as we grow more prosperous, that growth will use less energy and make less CO2” Eriksen, DNV GL

By 2032, it predicts electric vehicles (EVs) will account for half of global car sales and there will also be a rapid uptake for electrified buses in cities. By contrast, it expects hydrogen to increasingly play a role in long distance and heavy trucking.

DNV GL forecasts that adoption of EVs—which Eriksen says are three to four times more efficient—will mean that overall emissions from transportation will be marginally lower by 2050, despite the global fleet expanding by up to 75pc. It also predicts there will be more that 1bn two or three wheeled vehicles in Asia by 2030 and "more than 70pc of them will be electric".

Aviation and maritime are not easily able to adopt electric propulsion, says Eriksen, but "innovation is likely to be enormous".

Global electricity grids are forecast to almost triple in size by 2050, measured in voltage kms, and be greatly more efficient. "Electrification is the main theme in our forecast. We expect electricity, as an energy carrier, to more than double over the next three decades and electrification is a big driver for energy efficiency," says Eriksen.

"By mid-century, 63pc of the world's electricity will be supplied by solar PV or wind. This large share of renewables requires more flexible systems and that means huge increases in storage—we expect storage capacity to expand nearly fifty-fold… If there is one word to characterise the future grid it is complexity… and digitalisation is the key enabler."

Uruguay

]]>29018Serica thirsty for more9/10/2019 8:54:32 PMhttps://www.petroleum-economist.com/articles/politics-economics/europe-eurasia/2019/serica-thirsty-for-moreCraig Guthriehttps://www.petroleum-economist.com/media/4004/north-sea-platform-1.jpgNorth Sea oil and gas producer Serica Energy is aiming for further deals to complement its $370mn acquisition of three BP fields in the last year, according to the firm's CEO Mitch Flegg. But the focus is on specific assets rather than the portfolio sales that have characterised the region's M&A landscape of late.

The Aberdeen-based firm's leadership credits its steely focus on enhanced recovery and cost-cutting for a rise in gross profits by 30.6pc to $22mn last year. With its deal to take a 98pc stake in Bruce, 50pc in Rhum and 100pc in Keith, all previously operated by BP, coming into effect from 1 January 2018, full-year production rose to over 24,000 bl/d, from just 2,000 bl/d in 2017.

London-listed Serica does not benefit from the deep pockets of private equity (PE) backers. And, it also had to overcome the challenge of securing a waiver from US sanctions on Iran for Rhum, as the asset is co-owned by the National Iranian Oil Company (NIOC).

Unlike Serica, the swathe of nascent North Sea players is backed by PE cash. These firms will want an exit at some point-what are their most realistic exit strategies?

Flegg: It is difficult to see sufficient appetite in the market for a number of IPOs closely spaced together every couple of months. There are now some big PE-backed operators in the North Sea, and I just do not think that there is enough interest for them all to come to the market.

Whichever firm goes first will stand a good chance—and will probably use up a lot of the available capital. I am not sure how easy it will be for the firms that go second, third, fourth, fifth and sixth.

Some of the PE-backed firms will probably need to tidy up their portfolios by selling some of the assets that do not fit comfortably there. This may make the companies smaller and more attractive for an IPO, or alternatively for some sort of corporate activity or merger.

From our perspective, Serica is happy about that. We are buyers at the moment and are always looking for new opportunities. If there are assets on sale, we are enthusiastic about that.

Are there more big deals on the horizon along the lines of the BP purchase?

Flegg: We are certainly looking to repeat what we have done and continue to look for deals where the firm can add value. The company is not, however, going to join in big auctions such as the Chevron and ConocoPhillips sales.

Instead, the firm will continue to look for opportunities similar to our experience with Erskine, and then with the Bruce, Keith and Rhum fields—assets that we think will be better operated by us than the current owner.

What does Serica aim to bring to new assets in terms of cost cutting and efficiency?

Flegg: The biggest issue is focus and making sure the team does not get sidetracked onto unnecessary tasks. It is equally important to not be overambitious or overpromise. Our existing assets were, of course, previously owned by majors, which have more options on where to spend time and money. For us, everyone in the organisation is focused solely on a handful of offshore assets, and that is how Serica keeps costs under control.

This is not to be critical of majors, which do many tasks very well. Cost control is simply harder for them because people and resources are constantly switching between projects.

Do the annual waivers on Iran continue to be an issue? Or is the process more straightforward now?

Flegg: Serica requires an annual licence from the US Office of Foreign Asset Control and this year's one expires at the end of October. But we have been in regular communication with the US and were over in Washington about six weeks ago. The procedures and processes put in place for our first licence are still there, so it should be straightforward on 31 October.

]]>29017Shipping must start planning for zero CO29/10/2019 6:48:47 PMhttps://www.petroleum-economist.com/articles/midstream-downstream/tankers/2019/shipping-must-start-planning-for-zero-co2Alastair O’Dellhttps://www.petroleum-economist.com/media/4389/nigeria-products-tanker-1.jpgThe shipping industry must start work on technology, finance and business practices very soon if it is to comply with the International Maritime Organisation's (IMO) 2050 net zero emissions target, delegates heard at a London International Shipping Week (LISW) event this week.

Despite a deadline in more than thirty years, a combination of research and development, building and long lifecycles means that container ships commissioned in the next few years will still be in service when the deadline falls. Zero emission vehicles—or ones that can be retrofitted with zero emission engines—will therefore need to be designed in the next few years.

Bob Sanguinetti, chief executive, UK Chamber of Shipping, says the targets that the IMO have set are "hugely, hugely ambitious," and notes that the UK government has set even more stringent targets in its clean maritime plan.

"We are confident that the improvements needed to achieve the targets in 2030 can be achieved with existing technology," he says. "But when it comes to 2050, the technology to achieve net zero is just not there at the moment. It is a massive challenge… It is something that has to be done internationally."

In order to achieve the 2050 target, zero emission vessels need to be entering the fleet in 2030 and perhaps commissioned in 2027, says Katharine Palmer global head of sustainability, marine & offshore at maritime classification society, Lloyd's Register. In effect, the industry has just eight years to design suitable vessels.

"An asset being built in 2030 is going to have a lifespan of 20, 30 plus years so we need to start thinking about these designs now. People say we have plenty of time to do this, but, really, we do not. We need to start thinking about what we can do now so that a new build in 2030 can be retrofitted. What does that transition curve look like?"

"Are we really going to be carrying twice or three times as much fossil fuels in 2050?" — Sanguinetti, UK Chamber of Shipping

There are three ways of reducing the projected 3bn t CO2e in 2050 to the IMO's absolute maximum target of 450m t, according to Martin Stopford, non-executive president of research services at shipbroking firm Clarksons—move less cargo, slow down ships and come up with zero carbon power plants.

"The one [option] no-one wants to talk about is moving less trade," he says. "Sea trade has grown by 27pc since 2008. It was 8bn t, now it is 12bn t. Can we really afford to ignore that sort of escalating growth so that it gets to 30 bn t in 2050? I do not think so. The right decisions are not just about technology but about common sense and management.

"Today, 40pc of the cargo we carry is fossil fuels. Are we really going to be carrying twice or three times as much fossil fuels in 2050? I do not think so."

Paul Stuart-Smith, founder of consultancy Zero Carbon Finance and former COO of derivatives trading at the Baltic Exchange, says one of the key challenges to achieving zero emission shipping will be attracting the necessary capital. "The amount of capital needed will be vast. So it is critical, not only that it happens, but that it happens as efficiently as possible."

Investors are increasingly being guided by the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD), says Stuart-Smith. "The idea is to get companies in all sectors, including shipping, to confront the risks and opportunities of climate change and disclose these in their mainstream reports to investors-banks, pension funds and asset managers—to allow them to understand how companies are assessing and managing the risks of climate change."

More than 800 companies worldwide are supporters of the TCFD although "the ranks in the shipping industry are still low… but I think that is about to change because of the rapidly growing risks from climate change".

The most immediate hurdle for the industry is to comply with IMO 2020, which decreases the maximum allowable sulphur content from 3.5pc to 0.5pc on 1 January 2020.

"It has really taken off. So far this year, we are almost at the point where we have put more gas into the pipeline network than in the period from 2011 up to and including 2018. Of course, I would like to say that all this is because I joined Gate terminal in November," Groenendijk jokes. "But reality compels me to say that that was just a lucky coincidence."

A recent spike in new liquefaction capacity has been greater than the growth in LNG demand, prices have fallen globally and made Europe a more attractive destination, says Groenendijk. "If I look at the fact that quite a few [liquefaction] projects are coming on stream—there could be other factors of course—then I would say the period of LNG being rather plentiful may well continue for some time, maybe even a few years."

After several months of running at close to full capacity, the Gate terminal managers decided in March to test market appetite for increasing the send-out rate by 2bn m³/yr in an open season. Despite a few expressions of interest, the open season closed at its mid-April deadline with no firm agreements. "We are in discussion with customers. We will have to see where that will go," Groenendijk says.

Gate managing director Wim Groenendijk

For now, Groenendijk has his eyes set on new services. In late 2016 the terminal added a new jetty that can accommodate smaller vessels, including LNG bunkering ships. The Port of Rotterdam is expecting sales of LNG as a marine fuel in its waters to rise to 30,000t this year, a more than threefold increase from last year's sales of 9,500t. By 2025-30, the port foresees this figure reaching 1mn t.

As the port's only LNG facility, Groenendijk hopes Gate can count on booming LNG bunkering business at his small-vessel jetty, and studies into further expansion are ongoing. "[The small jetty] is something we are really studying to expand. It is a matter of 'how' rather than 'if'," he says. "We need to prepare for building some additional infrastructure. From the current jetty 3 we need to expand to more jetties, 4 and 5 maybe. And possibly even more."

Since 2014, Gate has also offered LNG loading onto trucks, now from three loading bays. As some of these vehicles also service the LNG bunkering market, Groenendijk is ready to build further bays if necessary, he says, adding that last year's record of over 2,800 fueled trucks will probably be surpassed by the end of December. "The month of August was a new monthly record of 343 trucks. Things are looking good, we see some growth there."

But competition in this niche market is already heating up, with Belgium's nearby Zeebrugge terminal offering two truck loading bays and the Dunkirk LNG terminal in northern France, only some 300km away, gearing up to open its first truck loading bay by the end of this month. "That will probably take away some of our market," Groenendijk admits. "In the past, our trucks went all over Europe, but we are seeing that market becoming more local."

Groenendijk's team is also studying the feasibility of distributing LNG by rail, which would be a first in Europe. Train connections from Rotterdam are excellent into the rest of the Netherlands but also to Germany, he says. "We are already discussing with a few prospective customers who have approached us. We are looking at how much it would cost, what could be the potential volume that could go that way, what would be the tariffs we need to charge."

]]>29007Prince Abdel Aziz takes the Saudi energy helm9/9/2019 10:58:40 AMhttps://www.petroleum-economist.com/articles/politics-economics/middle-east/2019/prince-abdel-aziz-takes-the-saudi-energy-helmGerald Butthttps://www.petroleum-economist.com/media/6867/riyadh-downtown-1.jpgNew Saudi energy minister Prince Abdel Aziz bin Salman has long been regarded as a potentially ideal candidate for the post. But the notion was always dismissed on the assumption that the tradition of a commoner technocrat heading the ministry would be maintained.

Now this tradition, like others since Mohammed bin Salman (MbS) rose to power under his father's auspices, has been broken.

The newly appointed minister, a half-brother of MbS and nearly twice his age, joined what was then the petroleum ministry as an advisor in the late 1980s, rising to take several junior ministerial positions. Prince Abdel Aziz had various areas of responsibility—at one point during Ali Naimi's tenure he co-ordinated a campaign to try to persuade Saudis to be mindful of energy waste. This has since become a central theme in MbS's Vision 2030 economic reform programme.

In international energy circles, Abdel Aziz was referred to simply as "the prince", a respected and liked member of the ruling family for whom further promotion appeared impossible because of his royal blood. His face became familiar at Opec meetings and other gatherings.

While he is related to MbS, the two men are very different in character and temperament. Where the crown prince can be abrasive and impulsive, Abdel Aziz is reserved and thoughtful. How their relationship will evolve remains to be seen. The likelihood is that MbS will be the architect of oil price policy, with his half-brother being the kingdom's public face at international gatherings.

Oil policy change?

The big question is whether the change of leadership at the energy ministry heralds a shift in strategy. Hints of dissatisfaction with the current state of Opec+ appear in an editorial in the influential Saudi daily al-Riyadh, beneath an article announcing the dismissal of the previous minister, Khalid al-Falih. The paper said the kingdom in August had reduced oil production to 9.83mn bl/d, well below the 10.31mn bl/d Opec+ allocation, "because it sensed danger coming to the market after some producing countries, inside and outside Opec, abandoned their commitment to produce the specific quantities agreed upon".

The kingdom did not name and shame the culprits, but has itself borne the effects of their non-compliance. The editorial went on to say that Saudi Arabia's efforts to support oil prices "may at times involve increasing production to meet shortages that may occur here or there".

Where the crown prince can be abrasive and impulsive, Abdel Aziz is reserved and thoughtful

In other words, Saudi Arabia appears to be growing impatient with making the biggest output cuts while others flaunt their Opec+ commitments—and may look to be more aggressive should further geopolitical tumults take more barrels out of the supply mix.

Shortly after Falih had been relieved of his chairmanship of Aramco, and when the industry and mining responsibilities had been removed from his ministry, the official Saudi news agency said MbS had held a telephone conversation with the Iraqi prime minister. The conversation centred on the importance of co-ordinating oil policies to support prices. It is likely the Saudi crown prince expressed dissatisfaction at what the kingdom regards as Iraq's inadequate adherence to the Opec+ deal. But the fact that MbS himself made the call, rather than Falih, was the first solid indication that the minister was soon to be out of a job.

His replacement by Prince Abdel Aziz constitutes a further consolidation of power by the Salman branch of the ruling family. Aside from the throne itself, members of the Salman line occupy the positions of deputy premier, crown prince and defence minister (MbS), energy minister (Abdel Aziz bin Salman), deputy defence minister (Khalid bin Salman), governor of Madinah province (Faisal bin Salman) and deputy governor of the Eastern province (Ahmad bin Fahd bin Salman). MbS also chairs the Council of Economic and Development Affairs and the Council of Political and Security Affairs.

]]>29004Majors' capex ignores Paris Agreement risk9/6/2019 5:02:14 PMhttps://www.petroleum-economist.com/articles/low-carbon-energy/renewables/2019/majors-capex-ignores-paris-agreement-riskAlastair O’Dellhttps://www.petroleum-economist.com/media/6865/paris-sall.pngEvery oil and gas major last year sanctioned investment in projects that would not produce sufficient returns if national leaders stick to their commitments to the COP 21 Paris Agreement, according to a new report by NGO Carbon Tracker.

"There is a finite limit to global carbon emissions that can be released for the world to reach the goals of the Paris Agreement—the carbon budget. We find that no oil and gas companies currently reflect these limits in their investment processes," report co-author and analyst Mike Coffin tells Petroleum Economist.

The 2015 agreement requires governments to constrain greenhouse gas emissions to levels that equate to global warming remaining 'well below' two degrees above pre-industrial levels. President Trump withdrew the US from the commitment in 2017 but 194 countries including China, by far the world's biggest greenhouse gas emitter, remain signatories.

The Carbon Tracker found that projects already sanctioned would take the world past the 1.5ºC target, assuming carbon capture and storage remains sub-scale. It also found that none of the oil sands projects sanctioned in 2018 work in a Paris-compliant world and several US shale specialists have portfolios entirely outside the climate budget.

Investor responsibilities

Pension schemes are increasingly being required to consider the financial risks attached to long-term investments in industries that may be impacted by climate change.

"Our analysis shows that since the start of 2018, all of the majors, including the European companies, have sanctioned projects that fall outside a 'well below' two degrees budget," says Coffin. "If investors wish to have Paris-aligned portfolios then they will want to challenge oil majors' investment in such projects."

Several UK pension schemes are even considering whether to invest in clean energy in emerging markets as a cost-effective way of mitigating emissions and complying with regulations that take effect in October.

"Investing in oil-hungry companies won't provide the dividends [funds] need to pay members when they take their pension in 30-40 years" — Martin, Share Action

"Investing in oil majors brings with it the responsibility to open up a critical dialogue and engage forcefully with these boards," says Jeanne Martin, senior campaigns officer at UK think tank ShareAction. This means asking companies to publish "new business strategies aligned with the Paris climate goals—instead of throwing capex at projects that will be defunct in a world soon to be dominated by low-cost, cleaner energies".

The Carbon Tracker report provides some "compelling evidence" that current plans are fundamentally misaligned with Paris, Martin adds. "Pension funds should be particularly alert to these financial risks, as more and more young people start saving for a pension. Investing in oil-hungry companies will not provide the dividends they need to pay members when they take their pension in 30-40 years.

"Pension schemes should be having these conversations with their asset managers, and escalating engagement with fossil fuel companies by supporting and filing shareholder resolutions that ask for strategies aligned with climate science and voting out directors of climate laggard companies."

"Pension funds are generally diversified and should consider the impact of climate change and the energy transition across their entire portfolios," says Carbon Tracker's Coffin. "Accordingly, it is in their interests to mitigate climate risks, including through engagement with fossil fuel producers."

Room for improvement

The report identified four large European companies—BP, Shell, Total and Equinor—that were "doing the most to reassure investors that they are responsive to climate concerns" but still approved projects that would not deliver adequate returns in a low-carbon world. Each fared better than the other majors and independents mentioned in the report.

BP has "supported the aim of the Paris Agreement" since it was agreed, the firm says. "Our strategy is to produce advantaged barrels, which involves considering factors like whether they are economic to produce, low risk to bring to market and lower carbon from an emissions standpoint."

The IEA forecasts that the world could still require 70mn bl/d oe of oil and gas in 2040, even in a Paris-consistent scenario. BP is "determined to supply the most advantaged barrels to meet that need". As competitive barrels are discovered, "they could help to push other more costly and high-carbon barrels out of the mix," just as gas is replacing coal. "It makes financial and environmental sense."

BP spent around $0.5bn of capex on renewables during 2018. "Our production is coupled with our renewables spend… and our robust work to reduce emissions, improve our products and create low carbon businesses," the firm says.

"All of this is aimed at evolving BP from an oil and gas focused company to a much broader energy company so that we are best equipped to help the world get to net zero while meeting rising energy demand."

]]>28994Brazil prepares for a big win9/6/2019 2:54:32 PMhttps://www.petroleum-economist.com/articles/upstream/licensing-rounds/2019/brazil-prepares-for-a-big-winCharles Wainehttps://www.petroleum-economist.com/media/6857/brazil-celebration-1.jpgBrazil has significantly liberalised its upstream sector and established a far more investor-friendly business climate since the Lava Jato-led corruption investigation sparked regime change. Brazil held six bidding rounds during 2017-18 alone, including five that focused on the prolific pre-salt region. These six auctions resulted in the sale of 72 blocks and achieved $7.5bn in signature bonuses.

The Brazilian regulator, the National Agency of Petroleum, Natural Gas and Biofuels (ANP), estimates the combined auctions added 2.5mn bl/d to peak oil production and $112bn in new investments across the country.

The government has scheduled a further three auctions to be held before year-end. The Transfer of Rights Surplus Bidding Round—certainly the highest profile and most lucrative for both government and industry—will be joined by the 16th concession bid round and the sixth production sharing round. Combined, they promise to generate a minimum of R$117bn ($28.4bn) in signature bonuses.

"The government needs these fields to be auctioned as soon as possible, both to see the signing bonus cash entering government accounts in the short term and to unlock investment potential. These are among the largest E&P offshore projects in the world—and have the capacity to put Brazil among the largest oil producers in the world," says Felipe Feres, partner at Brazilian law firm Mattos Filho. "In view of the energy transition, it might be the last opportunity to monetise these projects and see long-lasting benefits to the country's population."

Unique opportunity

The Transfer of Rights Surplus Bidding Round is scheduled for 6 November. It is a highly unusual auction because the reserves are entirely proven, so no exploration is required, and an incumbent operator will remain heavily involved. The four pre-salt fields—Buzios, Itapu, Atapu and Sepia—form the basis of what looks set to be Brazil's largest ever hydrocarbon auction.

“Buzios is definitely the jewel in the crown” Feres, Mattos Filho

Signature bonuses across the four fields, all available under production sharing regimes, are fixed and would generate R$106.5bn. An estimated R$52bn (depending on the result of legal proceedings) will go to the federal government, which it says will be used to pay down the national debt, with the remainder split between states, municipalities and state oil giant Petrobras.

The Brazilian government had discussed a surplus auction for the Transfer of Rights region ever since exploration in the area revealed hydrocarbon reserves in excess of the 5bn bl oe guaranteed to Petrobras. But for several years the government and the national oil company had disputed contract terms and compensation owed, which led to potential auctions being shelved. The two parties finally reached a settlement on the contract revision in April when the government agreed to compensate Petrobras $9.1bn. Companies taking part in the bid process will also be required to reimburse Petrobras for the investments it has made in the fields on offer.

Buzios and Itapu

The largest field available at auction is Buzios, in the Santos Basin. "Buzios is definitely the jewel in the crown, being by far the largest field on offer and one of the largest ever offshore E&P projects in the world," says Feres.

In 2010, Petrobras was granted the rights to produce 3bn bl oe from the field. It operates four platforms in the field, each with the capacity to produce 150,000bl/d of oil and 7mn m³/d of natural gas. Petrobras plans to add a fifth unit by 2022 and has committed $9bn of capex to develop the field through to 2023.

“Some of the majors could be frustrated with how the unitisation framework… was set-up” Romeo, Macquarie

The Brazilian state-owned oil company exercised its pre-emptive right to a 30pc share of the field and could yet increase its stake during the auction. The signing bonus for the field hugely exceeds all others at R$68.2bn—almost two-thirds of the Transfer of Rights total—and interested parties must offer a minimum of c.23pc profit oil to the government.

Petrobras also optioned a 30pc interest on the Santos Basin's Itapu field, the smallest available. The field was included in the company's 2019-23 business plan and a floating production storage and offloading (FPSO) vessel tender will be submitted after the auction. The FPSO will have oil capacity of around 120,000bl/d, as well as 3mn m³/d of natural gas, and is planned to be operational by 2023. The signing bonus for the field stands at R$1.8bn and bids must include a minimum c.20pc of profit oil.

Atapu and Sepia

The final two fields available in the Santos Basin are Atapu and Sepia, which differ in that Petrobras has waived its pre-emptive rights. Petrobras has already contracted a P-70 platform to enable the Atapu field to begin first production by 2020 and committed $2.7bn of capex before 2023. The field has been unitised with the surrounding Berbigao and Sururu fields, which are controlled by a consortium of operator Petrobras (42.5pc), Shell (25pc), Total (22.5pc) and Portuguese firm Galp (10pc). In its business plan, Petrobras pledged $1.7bn of capex to the Berbigao and Sururu fields. The signing bonus for Atapu stands at R$13.7bn, with minimum profit oil of c.25pc.

The Sepia field is projected to begin producing first oil by 2021 and Petrobras has agreed to lease a platform from Japanese floating platform firm Modec. Both the Sepia and Sepia Leste fields have been unitised into a single project within the BM-S-24 block, which is controlled by a consortium of operator Petrobras (80pc) and Galp (20pc). The signing bonus for the field is R$23bn and the minimum profit oil is the highest among these fields at c.28pc.

Petrobras has often declined to bid on a field where it had previously waived its pre-emptive right. Felipe Boechem, partner and head of oil and gas at Brazilian law firm Le Fosse Advogado, notes that "in the third PSC bid round, Petrobras bid for the two blocks in which it had exercised its preferential right and did not bid for the remaining two" for which it had not.

Source: ANP

In the fourth PSC bid round, Petrobras again submitted a bid on three blocks where it had earlier exercised its right but shunned the remaining one where it had not. It was only during the fifth PSC bid round that it chose to bid on a block it had previously opted not to exercise its right on.

International interest

Several major oil companies have indicated potential interest in the surplus auction. Neil Chapman, senior vice president of ExxonMobil, speaking on the company's Q2 results conference call, pointed to Buzios as the most tempting field on offer. "Because it is so large, everybody in the industry will have a look at it," he said. "I would be very surprised if they did not."

“I do not expect to see a large number of competing bids for each block, and potentially to see Petrobras involved in all of them” — Rhodes, CMS

But ExxonMobil is not interested in bidding based on size alone. "The way I look at it, we have to bring an advantage versus everybody else in the industry… a way where we can bring a significant advantage, get more value for our shareholders and not just get into a bidding war versus other players. We want to be able to bring an advantage to that resource, should we want to participate," says Chapman.

In February, Norway's Equinor stressed the potential opportunities presented by the Transfer of Rights auction and the growing importance of its Brazilian assets. The firm is targeting 300,000-500,000bl/d by 2030 and by 2025 four of Equinor's highest net present value assets will be in Brazil, according to Margareth Ovrum, executive vice president of development and production at Equinor Brazil. "The Transfer of Rights Surplus volumes could be an opportunity this year, if commercially attractive," she says.

Bidders will most likely seek to be in a consortium with Petrobras, in the view of Ted Rhodes, managing partner at law firm CMS. "We saw in the first production sharing bid round for the Libra field that many of the potential bidders sought to negotiate a joint bid with Petrobras, and the round ended up with a single bid for the minimum profit oil allocation to the government," he says. "It is possible that something similar could happen this time. I do not expect to see a large number of competing bids for each block, and potentially to see Petrobras involved in all of them."

Cost concerns

Recent comments from senior figures at majors suggest high entrance costs are tempering excitement. Bob Dudley, CEO of BP, said during the company's Q2 conference call that the fields on offer "look very expensive". "We are just going to remain very disciplined [and] within our capital framework," he says. We have not made a decision—we are still in discussions with Petrobras and looking at it. But we are going to be really, really careful."

Similarly, Galp, which has assets adjacent to the Atapu and Sepia fields, has concerns over the high fee. "Brazil starts to become relatively expensive, you can see by the bonus that has been released by the regulator," said CEO Carlos Nuno Gomes da Silva on the company's Q2 results conference call. "We have to do it in a prudent way, ensuring at least two or three elements that are relevant for us, so that we will be able to have reasonable returns. We will be capable of implementing strong partnerships that will get [us] access to assets of the right size." Brazil is now contributing around 98,000bl/d to Galp's upstream portfolio.

$7.5bn — signature bonuses 2017-18

Rhodes thinks the government sacrificed some of its revenue generation potential in order to maximise early revenues and help reduce its budget deficit. "The minimum profit oil share percentages for the government appear relatively low, and the cap on cost oil recovery of 80pc is relatively high," he says. "For companies with cash reserves, a low cost of capital and long-term vision, these blocks may prove attractive." In particular, he is looking towards Chinese state-owned companies, which are keen to secure long-term energy supply.

A further complication is the challenge of complying with three different fiscal regimes: the onerous assignment agreement, production sharing agreements and concession agreements. "The areas on offer are certainly attractive from a geological standpoint," says Boechem. "However, the overlap of different E&P regimes in the same area, which is very new and unique, gives rise to questions and risks with which bidders have never dealt." In addition, some of the issues can only be resolved after the auction, such as negotiation of the co-participation agreement and definition of the compensation owed to Petrobras for investment already made.

"Some of the majors could be frustrated with how the unitisation framework within the existing Transfer of Rights resources was set-up," says Romeo Giacomo, senior analyst at Australian bank Macquarie.

Rhodes agrees, cautioning that "the very significant cash outlays, the need for incoming private participants to negotiate a co-participation agreement with Petrobras, and potentially to unitise with other areas held by Petrobras, may make oil companies reluctant to bid except in a consortium with Petrobras".

Source: Petroleum Economist

]]>28990Guyana tipped for another find9/6/2019 12:34:48 PMhttps://www.petroleum-economist.com/articles/upstream/exploration-production/2019/guyana-tipped-for-another-findCraig Guthriehttps://www.petroleum-economist.com/media/6854/guyana-demerara-1.jpgGuyana is anticipating the announcement of another major oil find as early as next week, the country's chief investment official said at the SPE Offshore Europe conference.

"There have been some big discoveries and, by next Friday, we will be announcing another one", says Owen Verway, CEO of the Guyana Office for Investment, adding that he could not give more detail at this stage. "We are one of the hottest destinations for the oil and gas industry right now and that is set to continue."

The frontier province has been among the most successful upstream hotspots for the industry. Since 2015, ExxonMobil and its partners have made 13 discoveries offshore Guyana totaling around 5.5bn bl oe.

On 24 August, UK-headquartered Tullow, operator with a 60pc working interest in the Orinduik block, together with its partners Total (25pc) and Canadian independent Eco Atlantic (15pc), spudded the Joe-1 exploration well, saying results could be known in around three weeks. Earlier in August, Tullow announced that the Jethro-1 well in the same block contained more than 100mn bl oe of recoverable resources.

The oil finds are expected to have a major impact on the country of just 770,000, amid ongoing political uncertainty. In December, the David Granger administration suffered a vote of no-confidence but a promised election has been repeatedly delayed by appeals and voter registration issues.

5.5bn bl oe — ExxonMobil assets in Guyana

"GDP is going to double in a matter of 17 months," says Verway. "I do not believe another country in the world has experienced that speed of growth in the last century." In 2018, the country's GDP grew by 3.4pc to $3.6bn, according to the World Bank.

"There is a tsunami of cash investment coming into the economy, a huge increase in disposable income created by business activity."

To mitigate the chances of suffering under the resource curse that has affected other oil-rich countries, Verway notes that the country's energy officials are meeting regularly with officials from Scotland and the Canadian province of Newfoundland and Labrador to discuss policy, regulation, enforcement and development.

"There is a draft of the local content policy that will hopefully finalised by November, and a sovereign wealth fund draft that should be enacted very soon after parliament is formed," says Verway.

Commonwealth spirit

Greg Quinn, British High Commissioner to Guyana, says that British investors in particular should look at the country's potential. "On the fundamentals, Guyana is not only the only English-speaking South American country, it also has an English-language common law system", says Quinn. "The courts system is therefore very familiar to British companies. "

While there is bureaucracy and other issues around ease of doing business, for example electricity supply, as a Commonwealth country it shares a lot of values seen in the UK. "As a place for the British to work and do business, it will feel very familiar—apart from the sunny weather," says Quinn.

Lack of data

The process of legislating for the expected oil boom would benefit greatly from more detailed economic analysis, says Verway. "Decision makers need some critical analysis, projections to seize the strategic opportunities".

The Jethro discovery is an example of where there was a need for a value-chain analysis that could inform stakeholders. "How have situations like this played out in Scotland, in Newfoundland or in Houston?" asks Verway. "What is the investment required and the returns? That level of analysis still has not been conducted."

Source: Petroleum Economist

]]>28987BP gets Magnus money back9/6/2019 9:53:00 AMhttps://www.petroleum-economist.com/articles/corporate/finance/2019/bp-gets-magnus-money-backPeter Ramsayhttps://www.petroleum-economist.com/media/6852/magnus-oil-field-1.jpgUK independent Enquest has paid back the loan afforded to it by BP when the latter sold it a 25pc stake in the Magnus field in a January 2017 deal, the firm said when reporting results for the first half of the year.

The loan was repaid by Enquest through improved cashflow from Magnus, where the firm has increased production to above purchase case rates and reduced opex by 66pc from $60/bl oe in 2015 to $20/bl oe. "The key driver of our improved cashflow in the [first half of 2019] has been Magnus," says Enquest CFO Jonathan Swinney. "Improved performance from Magnus has accelerated the cashflow from the asset."

Enquest secured the 25pc stake in Magnus for a base consideration of $85mn, a price paid by a vendor loan from BP. That loan was fully repaid in August.

In September 2018, Enquest agreed to take up an option in the initial deal to acquire the remaining 75pc in Magnus. The base consideration for this deal was $300mn—although the 'economic date' of the transaction was set at January 2017. Cash flows from that point onwards were reclassified as accruing to Enquest, reducing the base consideration.

Enquest paid $100mn, which it raised through a right issues, towards the consideration, with the remainder—$200mn less cash flows accrued to Enquest—a second BP vendor loan.

The two firms also agreed to a subsequent entry into a 50/50 share of Magnus net cash flow from the 75pc stake, up to a maximum of $1bn to BP.

"The key driver of our improved cashflow in the [first half of 2019] has been Magnus" — Swinney, Enquest

In the second half of this year, Enquest expects to start the profit share arrangement on the 75pc stake, while still paying down the second vendor loan for the 75pc stake. It began its repayments in December 2108 and the repayment period is five years. At the point of entering the profit share arrangement, Enquest will have its $100mn, plus interest, repaid.

BP has entered into a number of innovation financing deals as it divests non-core North Sea assets, including its November 2017 deal with UK independent Serica for its stakes in the Bruce, Rhum and Keith fields. Serica agreed to pay BP £12.8mn upfront, as well as a share of cash flows over four years, 30pc of BP's post-tax decommissioning costs and additional payments dependent on future asset performance and oil prices.

Enquest also reported that it has reduced its debt-to-Ebitda ratio to 1.8 by the end of the second quarter, ahead of a target of under 2 by the end of the year. The firm would like to operate at the lower end of a 1-2 range, according to Enquest CEO Amjad Bseisu.

Fellow UK independent Premier Oil said in July that it had cut debt by $180mn, or almost 8pc, in the first six months of 2019 and is on target for a $300mn year-on-year cut, a figure that could be boosted by divesting its stake in the Mexican Zama discovery.

Despite Enquest's commitment to fiscal discipline, Bseisu did not rule out acquisitions, although its appetite may depend on the oil price. The firm has a "target-rich environment in its existing assets with very high payback and a low cost of development", says Bseisu. But pursuing the 20+ development opportunities around its key Magnus and Kraken North Sea assets may be more attractive if prices, and thus Enquest's cashflow, go up, and less so if prices are weak.

The North Sea is Enquest's "back yard" and it "will continue to look at opportunities selectively", says Bseisu. "What you have seen us do in late-life assets is differentiated," he continues, as the firm has proven it can "reduce costs very significantly".

]]>28984Falih moved aside as Aramco IPO looms9/5/2019 3:38:53 PMhttps://www.petroleum-economist.com/articles/politics-economics/middle-east/2019/falih-moved-aside-as-aramco-ipo-loomsGerald Butthttps://www.petroleum-economist.com/media/6850/khalid-al-falih-1.jpgSaudi energy minister Khalid al-Falih was once the man King Salman and Crown Prince Mohammed bin Salman (MbS) turned to when something needed fixing. While serving as Aramco CEO, he was appointed health minister to sort out a crisis in that department. He then became not only chairman of Aramco but also a minister with responsibility for energy as well as for industry and mining.

Now, in the space of a couple of days, Falih's role has diminished significantly. He is no longer the Aramco chairman; and the industry and mining responsibilities have been taken away from his ministry.

The new Aramco chairman is a former banker, Yasir al-Rumayyan. His appointment marks a new departure: it is the first time that a man with no oil experience has headed the Aramco board.

Rumayyan, a close aide of the crown prince, is also head of the Saudi Public Investment Fund (PIF), the body that is tasked with investing state money abroad as part of the aim to reduce the kingdom's dependence on oil revenue. This is the central plank in MbS' Vision 2030.

A key part of the strategy to raise money for investment is the planned initial public offering (IPO) of Saudi Aramco, discussed since 2016, but with details and timing of its implementation unclear. The latest jobs shuffle, an economics adviser to the Saudi government tells Petroleum Economist, "mean that they are going to have a real run at the IPO". "Since the money goes to the PIF, Rumayyan is the person to make sure interests are aligned. Obviously, he [the crown prince] did not feel Falih was so committed, and he was right," says the adviser.

In the past, Falih has privately questioned the wisdom of selling off part of the state energy company.

Jasta concerns

Details of when and where the IPO will take place remain elusive. In the past there has been a suggestion of a partial listing in the kingdom and then a broader one on a foreign exchange. MBS' preferred location is known to be New York. But lawyers have advised the Saudi authorities that there might be a risk of litigation under the US Justice Against the Sponsors of Terrorism Act (Jasta).

"Obviously, he [the crown prince] did not feel Falih was so committed"

Nevertheless, the adviser does not rule out the possibility that the crown prince will insist on New York for the listing. "Jasta and sovereign immunity vulnerability means they cannot list in the US without buying off the litigants, but maybe they will bite the bullet in that," he says.

Another possible reason for a further IPO delay is the current comparatively low global oil price. One of Falih's tasks has been to direct Opec+ efforts to ensure that a coordinated strategy of lowering production would boost prices. But the cuts have not achieved their goal.

For now at least, Falih remains energy minister and will have to decide whether or not the kingdom can risk losing market share by lowering output further. He will also urge his Russian counterpart, Alexander Novak, with whom he has a close relationship, not to abandon the current strategy.

But the Saudi crown prince wants to see a higher oil price, and he is a man who demands results from his appointees, no matter how great the challenges. He has shown how easily he can strip Falih of his Aramco chairmanship and some of his ministerial authority. Those who serve in high offices in Saudi Arabia these days know that their performance is under close scrutiny from the man who holds all the economic and political strings in the kingdom.

]]>28983China spearheading EV adoption9/5/2019 3:05:15 PMhttps://www.petroleum-economist.com/articles/midstream-downstream/vehicles/2019/china-spearheading-ev-adoptionDavid Whitehousehttps://www.petroleum-economist.com/media/6848/chinese-evs-1.jpgChina surpassed the United States as the number one crude oil importer in 2017 and again bolstered its import record in 2018, according to the International Energy Administration, while maintaining vast refining capabilities that exceed domestic demand.

But the country also has the fastest growing adoption of electric vehicles (EVs) and is a world leader in several forms of renewable energy. Together, these attributes mean it perhaps forms the most useful microcosm of how the global EV revolution will play out for the energy sector.

Passenger vehicles account for about a quarter of global oil demand. But BNP Paribas paints a dire picture for the future competitiveness of oil in the sector, in research published in August. It calculates that the long-term breakeven oil price to remain competitive as a source of energy for passenger cars for gasoline is $9-10/bl and for diesel $17-19/bl.

The oil industry has "never before in its history faced the kind of threat that renewable electricity in tandem with EVs poses," the report concludes.

The authors created the concept of energy return on capital invested (EROCI) to measure the amount of energy provided for mobility from investments in oil and renewables. For the same capital outlay today, wind and solar energy projects in tandem with battery EVs will produce between six and seven times more power at the wheel compared with oil.

“[The rise of EVs] may not be a smooth, steep upward slope” — Hari, Vanda Insights

The potential long-term implications for Chinese oil demand is striking if you consider the speed of electric car adoption. The Chinese government is spending billions of dollars to subsidise production of EVs and batteries as well as encourage their uptake. Chinese consumers bought 1.1mn EVs last year, more than the rest of the world combined and nearly triple the number purchased in the US.

Jack Barkenbus, a researcher at the Vanderbilt Institute for Energy and Environment in Tennessee, argues that China is likely to produce as much as 70pc of the world's EV batteries—a key determinant of electric car cost—by 2021, even as the demand for batteries grows.

The speed of oil's decline will be "inversely related to the battery technology curve," says Kristoffer Laurson, syndication director at Camco Clean Energy in London.

Petrol-powered vehicles will only be competitive for special applications in 10 years' time, he says. "Anything moving less than 300km per day will transition to electric at an accelerated pace since the payback is less than five years."

Incumbency advantage

In China, that downside risk is unlikely to unfold in a linear way. Oil has a "massive incumbency advantage," argues Dr Michal Meidan, director of the China Energy Programme at the Oxford Institute for Energy Studies.

Gasoline demand in China could peak in 2025 or so and start falling thereafter, she says, but China is still set to consume around 3.5-4mn bl/d of gasoline over the next decade. China's car fleet is still growing and, while the share of electric fleet share is rising, there is still "ample growth in ICE vehicles," Meidan argues.

Researchers at the Baker Institute for Public Policy at Rice University in Houston argue that the emergence of low-speed EVs—which cost as little as $3000—means that Chinese consumers do not need to be able to afford expensive EVs before they cease gasoline-powered driving.

But small vehicles that are suitable for local driving may not be so attractive to Chinese consumers in the long term. The Baker Institute says that if small EVs pushing down gasoline demand leads to lower pump prices, many consumers are likely to turn back to ICE vehicles; the evidence indicates that Chinese consumer demand is driven mainly by price considerations.

If economic constraints ease, particularly for relatively affluent consumers, the institute notes that a surge of road construction in China and the emergence of a more "American-style road trip culture" could drive gasoline demand increases at a pace that even rapid electric car penetration cannot offset.

Road demand from both freight and passenger vehicles in China is set to peak in 2025-30 while rail, marine and aviation numbers are all on the rise, according to Meidan. Moreover, demand for oil for use in petrochemicals is still rising in China and "will continue to grow for some time".

Matthew Parry, head of long-term research at Energy Aspects in London, agrees. He says that persistent demand from petchems and aviation will keep total Chinese oil demand rising until the late 2030s. He predicts that Chinese oil demand will increase by roughly 4mn bl/d between 2018 and 2040, or an average 1.3pc annual gain, led by jet/kerosene (+1.5mn bl/d), naphtha (+1.1mn bl/d), diesel (+0.7mn bl/d) and LPG (+0.6mn bl/d).

Spike in the tail

While a major evolution in mobility has arrived, according to Vandana Hari, founder of Vanda Insights in Singapore, it is "not a revolution". Government subsidies for car makers and buyers in China can boost the market for a while but they will have to be withdrawn at some point, she says.

Analysts have argued that the rush to electric and hybrid vehicle showrooms in June—which only took place due to the pre-announced scaling back of government incentives for buyers—augurs badly for longer-term demand. The China Association of Automobile Manufacturers in July reduced its forecast for 2019 new-energy vehicle sales from 1.6mn to 1.5mn units.

1.1mn — Chinese sales of EVs in 2018

Limiting factors—such as lack of adequate charging infrastructure, or under-supply of metals such as lithium and cobalt—will also delay electric-car take-up, Hari argues. The rise of EVs "may not be a smooth, steep upward slope".

Keun Wook Paik, senior research fellow at the Oxford Institute for Energy Studies, argues that BNP's oil price projection "seems to have underestimated the money politics" involved. Renewable energy is not yet a trillion-dollar business, he says. "Ultimately, it is a brutal money battle."

Wook Paik finds it difficult to imagine that China will allow the pendulum to suddenly shift from oil to renewables without taking protective measures. Beijing must consider the potential for mass unemployment that could be caused by a rapid transition from gasoline to electric cars, he says. "The collapse of gasoline-based car production would cause a massive social instability problem."

China is grappling with the contradictory challenges posed by poor air quality and potential social instability caused by large scale oil industry unemployment. They will leave "no stone unturned" to ensure a balanced energy sector transition, Wook Paik says. He expects Beijing will pay more attention to the expansion of natural gas in China's energy mix in coming decades. China is set to experience an era of 500-600bn m3 gas demand in 2030 and will be keen to source competitively priced LNG, he argues.

The first car purchased by hundreds of millions of Chinese people is likely to be electric. Many will never own a car that uses gasoline—but that does not mean that peak oil demand in the country can yet be predicted. Nothing guarantees that China will be able to make its energy transition smoothly; Hari sees the danger of underinvestment in the oil sector leading to "at least one more cycle of scarcity and a price super-spike" before Chinese oil demand begins to sustainably fall.

]]>28978Majors urged to lead energy transition9/4/2019 12:46:10 PMhttps://www.petroleum-economist.com/articles/low-carbon-energy/renewables/2019/majors-urged-to-lead-energy-transitionCraig Guthriehttps://www.petroleum-economist.com/media/6846/windfarm-forest-1.jpgInternational oil companies (IOCs) face a major challenge from investors pulling out of fossil fuel-related businesses but are also in a unique position to reshape public perceptions and become trusted custodians of the world's energy resources, a leading force behind the COP 21 Paris Agreement told the SPE Offshore Europe 2019 conference.

In the past four years over 1,000 institutions have together pledged to divest more than $6tn from fossil fuels, an 11,200pc increase over the previous period, says Christiana Figueres, executive secretary of the UN Framework Convention on Climate Change (UNFCCC) from 2010 to 2016.

"This capital drought is impacting IOCs more than NOCs," says the former Costa Rican diplomat, adding that the largest insurers and financial agents are also pulling insurance instruments from the fossil fuel business.

"[Oil] is in greater competition each day with EVs [electric vehicles] and renewables, although 10 years ago this would have seemed like science fiction. An estimated 35pc of oil demand comes from cars and 5pc from power generation, so effectively 40pc of global oil demand could be replaced."

Growing pressure

Pressure is being applied on IOCs from multiple sources. Last year, the 350.org divestment movement challenged investors to reach $10tn of divested assets by 2020 in order to deliver on the goals of the Paris Agreement. In July, oil and gas companies listed on the London Stock Exchange were reclassified as non-renewable energy.

"40pc of global oil demand could be replaced" — Figueres

IOCs could forge a new path by reinventing themselves as broader energy companies, says Figueres. Firms must also focus on radical methane reduction strategies and make dramatic investments in natural carbon storage initiatives, such as huge re-planting initiatives.

Political lobbying against climate change regulation would undermine rather than strengthen majors' position in the long term, she warns. "By doing this, you risk losing your 'licence to operate'. Anger on the streets at climate change is beginning to be matched by the fact that equity valuations in the sector have been stagnant lately, despite so much investment."

Earlier this year, Norway gave the go-ahead for its $1tn sovereign wealth fund, the largest in the world, to undertake the largest fossil fuel divestment to date, by selling off more than $13bn in coal and oil investments, although it stated at the time that the divestment programme was aimed at reducing the country's exposure to oil market volatility.

Privileged position

Figueres challenges the argument that moving away from oil and gas would have a negative macro-economic impact, although conceding that there will be an "unavoidable transition of the business model".

She reassures the oil and gas sector that it is in a "privileged position" to confront the challenge. "You could, of course, use that position to continue to explore [for oil] and continue to provide more supply." Instead, while there is a tough road ahead, Figueres says, the industry is "very ardently looking at… light at the end of the tunnel".

"The industry really is grappling with the challenges ahead," she says, adding that this enthusiasm is vital because "we do not have an option of [not] reducing emissions to zero by 2050—it is a necessity to ensure humanity's survival".

"Companies have moved on from the traditional adversarial relationship that existed [on the UKCS]. But we need to embrace technology more. There needs to be a 'next level' of cooperation," Sawan continues.

And fellow major Total tells a similar story. "If we increase the level of collaboration, we can deploy new technology earlier, delivering new tools to meet the problems that we face," says the firm's CEO Patrick Pouyanne. Despite, like Shell, slimming down certain areas of its North Sea portfolio, Pouyanne says that—not least for its relative political stability compared to Total activity hubs such as Russia, Nigeria and Angola—he "loves the North Sea," before adding "at least for the time being, even with Brexit".

That said, while Total's concentrated ownership in key Central North Sea and West of Shetland assets give it some scale, Pouyanne's description of the firm's global strategic focus—offshore conventional oil in low-cost areas such as the Middle East, giant deepwater projects in west Africa and Brazil, and LNG—is notable in the lack of fit even for its remaining North Sea assets.

More agile

"We need to create arenas where we can share knowledge competency," says Karl Johnny Hersvik, CEO of Aker BP, a joint venture between Norwegian industrial conglomerate Aker and BP, another European major that has rationalised its North Sea holdings.

Currently, only 3-5pc of available data at all stages of exploration and production is being shared by companies, and this is preventing companies from achieving greater efficiency through becoming leaner and more agile, says Hersvik.

"Digitalisation offers this industry its path to the future. We have already overcome the world's toughest problems to get to this point, and now we have the future in our hands. We could apply the same mindset, the same agility and the same functions that modern tech companies do to maximise the utilisation of our resources."

]]>28970Lebanon to struggle to replicate Israeli success9/3/2019 3:21:06 PMhttps://www.petroleum-economist.com/articles/upstream/exploration-production/2019/lebanon-to-struggle-to-replicate-israeli-successClare Dunkleyhttps://www.petroleum-economist.com/media/6840/tel-aviv-offshore-1.jpgIsrael's energy ministry awarded 12 blocks at the end of July, an encouraging return from the 19 blocks offered in its second ever offshore licensing round that closed earlier that month. But while it was an improvement on previous Eastern Mediterranean upstream auctions, it may not be entirely representative of what we can expect from future rounds.

In an attempt to learn lessons from its maiden auction in 2017—when only two bidders applied for, and were awarded, six of the 24 available blocks—Israel structured the offer to incentivise the acquisition of multiple contiguous blocks, located in the south and centre of its economic exclusion zone (EEZ).

In terms of the numbers participating, the strategy failed. Only two consortia choose to participate—a disappointment exacerbated by media reports that ExxonMobil and Petrobras had been considering bids. However, the clustering approach had the intended effect, with the result that most of the tendered blocks were apportioned.

A consortium led by Greece's Energean, along with local producer Israel Opportunity Energy Resources, acquired Cluster D, comprising four 400km² (154m²) blocks in the central EEZ. Energean is already Israel's third-largest operator; it is developing the northern Karish and Tanin fields and acquired five additional licenses in the first bid round. Further expansion outside the company's existing area of operations, buttresses the government's claims of good prospectivity across the EEZ.

Energean says that a prospect has been identified in the new acreage analogous to the known Tamar Sands fields, which include Karish as well as the giant Tamar and Leviathan fields managed by US producer Noble Energy and Israel's Delek Drilling.

For aspiring producers, current options are limited

Clusters A and C, each likewise comprising four 400km² blocks, were awarded to a joint venture of UK headquartered Cairn Energy and Soco International and Israel's Ratio Oil. Cairn has previously focused on Africa, the Americas and the North Sea, and, before that, South Asia. Soco made its MENA debut in April with the acquisition of Egypt-focused Merlon International and thereby of a producing concession in Egypt's Western Desert. Ratio has been a presence since the birth of Israel's offshore gas industry and was responsible for the discovery of the estimated 22.4tn ft³ Leviathan field in 2010. The company also owns the Royee licence, adjacent to Cluster C.

The key deterrents to wider participation remain those that afflicted the first bid round; most importantly, the lack of export outlets should fresh gas be unearthed. The domestic market, while expanding rapidly, is limited, currently served by Tamar production and due to be a significant recipient of Energean's Karish/Tanin development. Noble and Delek have pursued independent export solutions for Tamar and Leviathan, such as pipelines to Jordan and Egypt and potentially LNG facilities, but with only limited success.

For aspiring producers, current options are limited. The Israeli government trumpets the unbuilt East Med gas pipeline—a proposed 2,200km (1,367m) link from Israel to southern Europe. But the political, financial and technical challenges entailed are so enormous that uncertainty surrounds its future.

Source: Petroleum Economist

Lebanon's obstacles

Lebanon, a smaller market with no current gas production, faces even steeper obstacles in attracting interest in its offshore acreage, not least the overlap of the three of its 10 blocks with territory disputed with Israel. Like its neighbour, Lebanon elicited a weak response to the much-delayed debut bid round in 2017, with a sole bidder making offers for only two of the blocks.

However, the disappointment was mitigated by the calibre of the winning consortium, comprising Total, Italy's Eni and Russia's Novatek, and its willingness to drill in one of three contentious blocks, Block 9. The latest five-block auction, due to close on 31 January 2020, could be even more inflammatory; it includes the remaining blocks contested with Israel, two northern blocks infringing on waters disputed with Syria and a final licence area bordering Cypriot waters.

Furthermore, no export routes currently exist, with marketing focused on pent-up domestic demand. Nonetheless, energy minister Nada Boustani insists that interest is strong, adding that firms studying the acreage include BP and Russia's Gazprom and Lukoil, as well as the incumbent consortium.

Source: Petroleum Economist

]]>28968China and Iran flesh out strategic partnership9/3/2019 11:22:06 AMhttps://www.petroleum-economist.com/articles/politics-economics/middle-east/2019/china-and-iran-flesh-out-strategic-partnershipSimon Watkinshttps://www.petroleum-economist.com/media/6838/tehran-mountains-1.jpgIran's foreign minister Mohammad Zarif paid a visit to his Chinese counterpart Wang Li at the end of August to present a road map for the China-Iran comprehensive strategic partnership, signed in 2016.

The updated agreement echoes many of the points contained in previous China-Iran accords, and already in the public domain. However, many of the key specifics of this new understanding will not be released to the public, despite representing a potentially material shift to the global balance of the oil and gas sector, according to a senior source closely connected to Iran's petroleum ministry who spoke exclusively to Petroleum Economist in late August.

The central pillar of the new deal is that China will invest $280bn developing Iran's oil, gas and petrochemicals sectors. This amount may be front-loaded into the first five-year period of the deal but the understanding is that further amounts will be available in every subsequent five-year period, subject to both parties' agreement.

There will be another $120bn investment in upgrading Iran's transport and manufacturing infrastructure, which again can be front-loaded into the first five-year period and added to in each subsequent period should both parties agree.

Chinese presence

Among other benefits, Chinese companies will be given the first refusal to bid on any new, stalled or uncompleted oil and gasfield developments. Chinese firms will also have first refusal on opportunities to become involved with any and all petchems projects in Iran, including the provision of technology, systems, process ingredients and personnel required to complete such projects.

"This will include up to 5,000 Chinese security personnel on the ground in Iran to protect Chinese projects, and there will be additional personnel and material available to protect the eventual transit of oil, gas and petchems supply from Iran to China, where necessary, including through the Persian Gulf," says the Iranian source.

$280bn — Chinese investment in Iranian oil, gas and petchems sector

"China will also be able to buy any and all oil, gas and petchems products at a minimum guaranteed discount of 12pc to the six-month rolling mean price of comparable benchmark products, plus another 6pc to 8pc of that metric for risk-adjusted compensation."

Under the terms of the new agreement, Petroleum Economist understands, China will be granted the right to delay payment for Iranian production up to two years. China will also be able to pay in soft currencies that it has accrued from doing business in Africa and the Former Soviet Union (FSU) states, in addition to using renminbi should the need arise—meaning that no US dollars will be involved in these commodity transaction payments from China to Iran.

"Given the exchange rates involved in converting these soft currencies into hard currencies that Iran can obtain from its friendly Western banks—including Europäisch-Iranische Handelsbank [in Germany], Oberbank [in Austria] and Halkbank [in Turkey]—China is looking at another 8-12pc discount [relative to the dollar price of the average benchmarks], which means a total discount of up to 32pc for China on all oil, gas and petchems purchases," the source says.

Another positive factor for China is that its close involvement in the build-out of Iran's manufacturing infrastructure will be entirely in line with its One Belt, One Road initiative. China intends to utilise the low cost labour available in Iran to build factories, designed and overseen by large Chinese manufacturing companies, with identical specifications and operations to those in China, according to the Iranian source.

Transport infrastructure

The resulting products will be able to enter Western markets via routes built or enhanced by China's increasing involvement in Iran's transport infrastructure. When the draft deal was presented in late August to Iran's Supreme Leader Ali Khamenei by Iran's vice president, Eshaq Jahangiri—and senior figures from the Economic and Finance Ministry, the Petroleum Ministry and the Islamic Revolutionary Guard Corps—he announced that Iran had signed a contract with China to implement a project to electrify the main 900km railway connecting Tehran to the north-eastern city of Mashhad. Jahangiri added that there are also plans to establish a Tehran-Qom-Isfahan high-speed train line and to extend this upgraded network up to the north-west through Tabriz.

Tabriz, home to a number of key oil, gas and petchems sites, and the starting point for the Tabriz-Ankara gas pipeline, will be a pivot point of the 2,300km New Silk Road that links Urumqi (the capital of China's western Xinjiang Province) to Tehran, connecting Kazakhstan, Kyrgyzstan, Uzbekistan and Turkmenistan along the way, and then via Turkey into Europe, says the Iranian source.

The pipeline plan will require the co-operation of Russia, as it regards the FSU states as its backyard. And, because, until recently, Russia was weighing a similarly all-encompassing standalone deal with Iran. So, according to the source, the agreement includes a clause allowing at least one Russian company to have the option of being involved, also on discounted terms, alongside a Chinese operator.

Benefits for Iran

The Iranians expect three key positives from the 25-year deal, according to the source. The first flows from China being one of just five countries to hold permanent member status on the United Nations Security Council (UNSC). Russia, tangentially included in the new deal, also holds a seat, alongside the US, the UK and France.

“[The deal] will include up to 5,000 Chinese security personnel on the ground in Iran to protect Chinese projects”

"In order to circumvent any further ramping up of sanctions—and over time encourage the US to come back to the negotiating table—Iran now has two out of five UNSC votes on its side. The fact that [Iran foreign minister Mohammad] Zarif showed up unexpectedly at the G7 summit in August at the invitation of France may imply it has another permanent member on side," he adds.

A second Iranian positive is that the deal will allow it to finally expedite increases in oil and gas production from three of its key fields. China has agreed to up the pace on its development of one of Iran's flagship gas field project, Phase 11 of the giant South Pars gas field (SP11). China National Petroleum Corporation (CNPC), one of China's 'big three' producers, added to its 30pc holding in the field when it took over Total's 50.1pc stake, following the French major's withdrawal in response to US sanctions. CNPC had since made little progress developing SP11—a 30pc+ discount to the global market price on potential condensate and LNG exports could change that.

China has also agreed to increase production from Iran's West Karoun oil fields—including North Azadegan, operated by CNPC, and Yadavaran, operated by fellow 'big three' firm Sinopec—by an additional 500,000bl/d by the end of 2020. Iran hopes to increase projected recovery rates from these West Karoun fields, which it shares with neighbour Iraq, from a current 5pc of reserves in place to at least 25pc by the end of 2021 at the very latest. "For every percentage point increase, the recoverable reserves figure would increase by 670mn bl, or around $34bn in revenues even with oil at $50/bl," the Iranian source says.

A final Iranian benefit is that China has agreed to increase imports of Iranian oil, in defiance of a US decision not to extend China's waiver on imports from Iran in May. China's General Administration of Customs (GAC) figures released in late August show that, far from reducing its Iranian imports, China imported over 925,000bl/d from the country in July, up by 4.7pc month-on-month, from an already high base.

The actual figure is still higher, according to the Iranian source, with excess barrels being kept in floating storage in and around China; without having gone through customs they do not show up on customs data, but are effectively part of China's Strategic Petroleum Reserve.